Good morning, welcome to the Quicksilver first quarter 2009 Earnings Call. (Operator’s Instructions). I would now like to turn the conference over to Rick Buterbaugh, Vice President of Investor Relations. Thank you. Mr. Buterbaugh, you may begin your conference.

This morning, the company issued a press release detailing Quicksilver's results for the first quarter of 2009. If you do not have a copy of this release, you may retrieve a copy on the company’s website at www.qrinc.com under the News and Updates tab.

During today’s call the company will be making forward-looking statements, which are subject to risk and uncertainties. Actual results might differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed in the company’s filings with the SEC.

Today's discussion will include information regarding adjusted net income and net cash from operating activities before changes in working capital, which are non-GAAP financial measures. As required by SEC rules, reconciliations of adjusted net income and net cash from operating activities before changes in working capital to the most directly comparable GAAP measures are available on our website under the Investor Relations tab.

At this time, I will turn the call over to Glenn Darden to review our financial and operating activities in additional detail.

Glenn Darden

Thank you, Rick. Good morning. Quicksilver Resources had first quarter 2009 adjusted net income of $26.6 million or $0.16 per diluted share. This compares to $0.25 per diluted share in the 2008 period. The company had record production volumes of approximately 332 million cubic feet of gas equivalent per day.

In the Fort Worth Basin, daily production showed an 82% year-over-year increase and Canada daily production increased 4% year-over-year. Operationally, Quicksilver has slowed the drilling pace considerably. Recently, we trimmed the 2009 capital budget from $600 million to $500 million. Despite these budget cuts, the company anticipates keeping production volumes roughly flat with average fourth quarter 2008 production volumes. This would result in a year-over-year volume increase in excess of 20%.

In fact, we've identified an additional $50 million of potential capital savings, which would not affect production volumes. This certainly highlights the quality of our asset base. A big part of the reduced capital comes from a decrease in our drilling rig fleet.

We anticipate running five rigs for the remainder of the year in the Fort Worth Basin and will reduce drilling in our Canadian Horseshoe Canyon CBM project as well. Quicksilver took a non-cash impairment charge or ceiling test writedown of $594 million in the quarter related to the company's oil and gas properties.

Also, we took a non-cash impairment charge of $66 million in the quarter related to the company's equity investment in BreitBurn Energy Partners. Phil Cook will detail these write-downs later in this call.

The company continues to drive down costs both on the operating and drilling and completion side. We have reduced oil and gas production expense to $1.10 per Mcf equivalent, which is down 35% year-over-year. It is clear that our integrated model of production, gathering, processing, and firm transportation to better priced markets is giving Quicksilver a competitive advantage.

The company's average basis differential in the Fort Worth Basin for the first quarter was approximately $0.33 per Mcf, and we project it to be in the $0.20 per Mcf range for the remainder of the year. We're also making excellent progress on the liquidity side of the business.

Quicksilver's $1.2 billion credit facility was affirmed by our bank group recently, and we're making head way on several transactions that would reduce debt and give the company greater financial flexibility. We expect to see results of these efforts in the next several months.

The company has great assets and with a stronger financial structure will be able to realize the true value of those assets.

On the exploratory front, Quicksilver has drilled and cased two horizontal wells in the Horn River basin in northeast British Columbia. We have also built all-weather roads and gathering lines to tie these wells into sales line upon completion. Completion operations will begin later this summer when the surface conditions improve. Both of the initial wells had roughly 500 feet of combined Muskwa and Klua shale sections and core analysis and gas flares while drilling through these sections are encouraging.

The company also is working on another gas project, where we have assembled a sizable acreage position. We will discuss this new venture as the year progresses, but have no results to report today.

In addition, we have slowed the spending on our west Texas shale project in this low-commodity price environment.

In summary, Quicksilver's low-cost structure and high-quality assets combined with an excellent hedge position will enable the company to maintain current production with a predictable cash flow over the next two years.

As the company's liquidity improves and commodity prices rise, Quicksilver will be well positioned to accelerate growth and maximize value for our shareholders.

Now I will turn the call over to Phil Cook, our Chief Financial Officer. Phil.

Phil Cook

Thank you, Glenn, and good morning. Production volumes grew from 326 million cubic feet a day equivalent in the fourth quarter of 2008 to 332 million cubic feet a day in the current quarter, a 2% sequential increase. Production volumes grew 57% when compared to the same period a year ago and as Glenn said volumes in the Fort Worth Basin grew 82%, again, comparing against the same period a year ago.

Total production revenue grew 16% when comparing the same period a year ago after taking into account lower commodity prices. Our realized natural gas price for the first quarter was $7.04 after hedging compared to $7.49 in the fourth quarter, down 6%.

Natural gas liquids realized prices were $21.13 a barrel in the current quarter, compared to $26.86 a barrel in the fourth quarter, down 21%. Realized oil prices were $34.42 a barrel in the current quarter, down from $64.03 a barrel in the fourth quarter, a 46% decrease.

Total oil and gas expense for the first quarter was approximately $32.7 million, a 10% sequential decrease when compared to the fourth quarter expense of $36.1 million. On a unit basis, lease operating expense for the current quarter was $0.60 per Mcfe compared to $0.69 in the fourth quarter. Of this amount, approximately $0.04 is non-cash and is related to equity compensation for our operational employees. This amount excludes transportation, processing, and production tax expense, but as you can see our sequential reduction in LOE was 13%.

Transportation expense, which is the cost to get our gas from the tailgate of our facilities to market, was $0.34 on an Mcfe basis during the current quarter compared to $0.36 in the fourth quarter 2008. Most of this decrease is attributable to the fuel component of transportation expense due to lower commodity prices.

Processing expense, which is the cost to gather and process our gas from the wellhead to the tailgate of our facilities for the current quarter was $0.16 on an Mcf basis compared to $0.15 in the fourth quarter, essential flat sequentially.

So just as a recap, oil and gas expenses were broken down as follows. LOE was $0.60, transportation expense was $0.34, processing was $0.16, for a total of $1.10, which is an 8% decrease sequentially, when compared to the $1.20 achieved in the fourth quarter of 2008.

Based on our revised capital program and our expected volumes, we expect that LOE should begin to level off on both an absolute dollar basis and a per Mcfe basis.

Production taxes for the quarter were $0.15 a unit, a decrease from the $0.25 a unit reported in the fourth quarter. As you may recall, fourth quarter 2008 production taxes include first-time property tax assessments on a number of our properties, particularly related to assets in the Alliance area. We purchased Alliance in 2008. This entire expense was recognized in the fourth quarter.

The DD&A run rate for the current quarter was $2 a unit, a decrease from $2.08 a unit recorded in the fourth quarter 2008, which principally relates to the impact of recording the full cost ceiling test impairment during the fourth quarter of 2008. G&A was $0.58 on a unit basis for the quarter as compared to $0.53 in the fourth quarter. The increase in G&A expense is primarily due to increased legal fees.

G&A for the quarter includes approximately $0.16 of non-cash stock-based compensation expenses related to LTI plans for all of our employees. Therefore, on a cash run rate basis, G&A is about $0.42.

As a brief recap of total cash expenses for oil and gas expenses, expenses, production taxes and G&A were $1.63.

As you know, posted on the website is a detail by operating area of our production prices and operating costs. I'd like to touch on operating income for the quarter before impairment charge in contrast to the first quarter of 2008 with the current quarter to really point out the power of cost control. Throughout the 2008 year and into the current quarter we have focused on cost control at every level of the organization. In this period of time, when we were continuing to grow, we reduced our cash unit costs by over 30% going from a cash unit cost of $2.50 in the 2008 first quarter to the current quarter cost of a $1.63. Both of these unit cost amounts exclude approximately $0.20 of expense that relates to non-cash equity compensation for our employees.

The result of this has been that even though we have suffered an approximate $2 reduction in gas prices on an Mcfe basis, our operating income for the current quarter is flat with the 2008 quarter.

Adjusted net income for the quarter was $26.6 million or $0.16 of diluted share as compared to adjusted net income of $40.4 million or $0.23 a diluted share in the fourth quarter. First quarter 2009 adjusted net income does not include unrealized non-cash income of $91.3 million related to the fourth quarter marked-to-market income that BreitBurn recorded related to hedges. It also does not include the non-cash impairment charge that BreitBurn recorded of $22.8 million, related to its full cost ceiling test impairment and a non-cash charge that BreitBurn recorded of $4 million related to interest rate swaps.

Adjusted net income also does not include a non-cash full cost ceiling test impairment charge of $593.8 million related to Quicksilver's oil and gas properties which is due to the significant continued decline in commodity prices at quarter end as well as a non-cash impairment charge of $66.3 million that Quicksilver recorded associated with our investment in BreitBurn which reduced our carrying value of this investment to the 3/31/2009 market value of $6.53 a common unit.

During the first quarter the company generated approximately $149 million of cash flow from operations as compared to 43 million in the first quarter of 2008; a 246% increase. Capital expenditures were approximately $190 million. Cash spent in the first quarter with respect to capital which includes 2009 capital as well as 2008 capital, was $255 million. Including the $255 million of expenditures, the company intends to spend cash of approximately $500 million for the entire year or an additional $250 million between now and year-end.

We expect to generate cash for the year of $500 million including the $149 million we generated in the first quarter, which will allow us to pay down debt by approximately $100 million between now and year-end. All of that said, we will spend within cash flow for the year.

Our revolving credit facility which has a borrowing base that was reaffirmed on April 17th of $1.2 billion. Contrary to some of the notes written after the release, the interest rate increase on the revolver was 100 basis points from the previous rate.

Our fully drawn interest rate on the credit facility is approximately 4% and the weighted average interest rate on our entire debt portfolio is 5.4%, which are both very attractive cost of capital.

Our revolving credit facility at quarter end was approximately $917 million drawn on a borrowing base of $1.2 billion. Total Quicksilver debt at quarter end was approximately $2.5 billion which excludes KGS debt which is non-recourse to the parent. This amount of debt reflects the fact that we did borrow $100 million in the first quarter, but as I said we intend to repay from cash flow from operations before year-end.

As I discussed in our previous calls, the maturities on our debt don't begin until 2012 which is our credit facility which is extendible for two more years. We believe our maturities give the company significant flexibility regarding cash management over the next few years.

We continue to closely monitor the credit and financial markets, and although we presently expect to generate sufficient cash flow to achieve our drilling budget, we do have the flexibility, should conditions worsen to pay down debt and slow capital further.

Now I will make a couple comments about what to expect for the second quarter of 2009. Production volumes for the second quarter should be in a range of 330 million to 335 million a day on a gas equivalent basis. Also as a reminder approximately 75% or 190 million cubic feet a day of our 2009 natural gas production is hedged with a weighted average floor of $8.66.

With respect to unit costs the following run rates should be expected for the second quarter. LOE should be in a rage of $0.60 to $0.65. Transportation expense should be in a range of $0.30 to $0.35, gathering processing expenses should be in a range of $0.15 to $0.17 for total operating cost of $1.05 to $1.17.

Production taxes should be $0.14 to $0.16 and G&A should be $0.55 to $0.60. DD&A run rate should be between $1.70 and $1.75. Now I will turn the call back over to Rick for questions.

Rick Buterbaugh

Thanks, Phil. Jennifer, at this time I would like to open the call to any questions.

Want to follow up on some stuff you talked about last quarter with respect to the wells that have been drilled and put into inventory, so not completed. Where are you guys on that number right now; and how is that different from typical time period? You're always going to have some drilled and an inventory awaiting completion and tie. If you can kind of walk us through that, that would be very helpful.

Rick Buterbaugh

You bet, Dave. At year end we had approximately 120 wells that were drilled and cased in the Fort Worth basin but not yet completed. As we stated this morning, in the first quarter we had drilled an additional 26 wells and cased those wells and completed about 22 of them. So we have definitely slowed down the pace of drilling activity as Glenn mentioned as a result of reducing down to five rigs versus the roughly 12 to 14 rigs that we averaged throughout 2008.

We're working to maintain that level of inventory of drilled but yet to be completed wells at that 120. Now for the entire year, we expect to drill in the Fort Worth basin approximately 100 wells, and complete about 70 of those. So we'll have about 75 wells left to drill for the remainder of 2009, and complete about 50 more of those, which will build that inventory from 120 up to about 150 wells at year end 2009, which is a dramatic reduction from our prior estimates.

Dave Kessler - Simmons & Company

Okay, that's helpful. Then just typically, when we talk about drilling and uncompleted wells, there's always going to be a small inventory of that or an inventory of that. So just to get a clear sense of what is above and beyond what typically a company would have; what is kind of the average would you have had last year prior to starting to stack up these wells?

Rick Buterbaugh

It's probably double the inventory, David, roughly.

Dave Kessler - Simmons & Company

Okay. Maybe I'm not asking it clearly. I would imagine it would be less than the current inventory.

Rick Buterbaugh

It would be about half. It's going to fluctuate based upon what type of pads each rig is drilling on, but because of the multi-well nature of each pad, it's normal to have a significant inventory of drilled but yet to be completed wells.

Dave Kessler - Simmons & Company

That's what I was trying to get at. Thank you for clarifying that. And then just on the call you mentioned that there are several potential transactions in the pipeline to create additional liquidity. Can you give us any color in terms of what all those various options are, the options that you would be pursuing at this point and the magnitude of the capital that could be raised through those options?

Rick Buterbaugh

Well, I'll leave it like this, David. We've got several projects on parallel tracks that we're working on to de-lever the balance sheet, and we've talked a bit about joint venture type transactions, those structures. Perhaps there's some refinancing of existing debt on better terms and covenants, and that's not truly de-levering, but on the de-levering side, they would make a significant impact.

Dave Kessler - Simmons & Company

Okay. Is there a goal that you guys are striving towards? Just trying to get a sense for just keeping track where you are and where you want to be.

Rick Buterbaugh

Sure. We do have, and are internal goals, and I think it will become much clearer in the next couple months.

Operator

Your next question comes from Ronny Eisemann with JPMorgan. There is no response. We'll go to the next question in queue, Mike Scialla with Thomas Weisel Partners.

Mike Scialla - Thomas Weisel Partners

Can you talk at all about the new venture in general terms, maybe what the acreage size is and what you have paid for it? Is it in an established play, or is it something new that you're looking at on your own?

Phil Cook

We are preferring not to comment on new ventures at this time, Mike. It's of comparable size to other projects we've had in inventory as far as potential goes, and we're working on several initiatives. So until we have results, we're electing not to make any statements.

Glenn Darden

What I would add to it Mike, this is Glenn, we've stated historically Quicksilver spent roughly 10% of its budget on exploratory or new projects on an annual basis, and those projects fit right with in that. Of course, you know that the bulk of our spending this year is going to be Horn River, so that's big but we've got another couple projects at different stages. So, we're not trying to be coy. We just want to have some solid results to talk about when we release information.

Mike Scialla - Thomas Weisel Partners

I understand. Are you still adding any acreage in the areas?

Glenn Darden

Possibly.

Mike Scialla - Thomas Weisel Partners

And would these be potential joint venture candidates as well?

Glenn Darden

They certainly could be, at appropriate time.

Mike Scialla - Thomas Weisel Partners

Okay. And then kind of look like your NGL volumes on a percentage basis of total production jumped up a little bit in the quarter. Is there anything behind that change in the production mix? I know Denbury had mentioned there were some NGL sale issues in the third, fourth quarter fall on the hurricanes. Did that affect you at all?

Glenn Darden

I think the primary increase, Mike is from the start-up of the Corvette plant and the reduction in line pressures, which are getting better yield from our gas volumes, and that is the largest driver of those increased volumes.

Mike Scialla - Thomas Weisel Partners

And then just wanted to get a sense for the cost reductions, what are you seeing now for completed well costs in Tarrant and Hood? For that matter, the EUR is changing there at all?

Glenn Darden

The EURs are roughly the same. The cost has probably come down, 25% across the board perhaps a bit more than that. So we're improving our economics if our gas price will help us a little bit, but certainly on our hedge volumes now.

Mike Scialla - Thomas Weisel Partners

So your typical Hood well now is, say, a pad well, is costing what?

Glenn Darden

Well, Mike, we're looking at it on a cost per foot of lateral, basically, because the [lateralings] vary quite a bit, so absolute cost per well really aren't a good measure of how we're performing. We're measuring our performance on a cost per foot of [lateraling].

Phil Cook

But in rough terms, if we had a $3 million well, we're in the 2.2 range, something like that, and in Alliance and Lake Arlington, where those wells were in the $4 million range, they're closer to $3 million today, a little bit better.

Mike Scialla - Thomas Weisel Partners

That helps. Last question, on the five-rig plan now, are you going to have to eat any penalties going down to five rigs, and are you letting any acreage go?

Glenn Darden

We're not letting any acreage go that we don't want to release, so we're keeping our core acreage intact, and we are paying some standby charges which are roughly a quarter of day rates, something like that to reduce our rig count of the contracted rigs.

Mike Scialla - Thomas Weisel Partners

And how many -- was that eight contracted rigs?

Glenn Darden

Four, yeah.

Operator

The next question will come from David Snow with Energy Equities.

David Snow - Energy Equities

Yeah, I'm wondering, is there any thought to doing anything with your holdings of the pipeline KGS or BBEP, as a way of re-liquefying?

Glenn Darden

Those are certainly in the thought process, but KGS is a little different strategically for the company because obviously controlling our midstream and our gas a little farther downstream, is important as our costs are reflecting. So over time, but every one of these assets that we have in the company we look at individually, and we have targets. Does BreitBurn make sense in our portfolio a long term? As we said before, probably not, but we're not very anxious to sell it at current prices.

David Snow - Energy Equities

I couldn't understand whether you meant your current uncompleted inventory in the Fort Worth Basin is double normal or half normal?

Glenn Darden

It's double normal. So 60 would be normal. We're at about 120.

David Snow - Energy Equities

Is that to hold acreage at a lower outlay, or what's the strategy?

Glenn Darden

One of the reasons, yes, David.

Operator

Your next question comes from Irene Haas with Canaccord.

Irene Haas - Canaccord

Hello, guys. Just a few questions here. You're still hanging on to a CapEx program of $500 million. I'm just kind of wondering, push come to shove are there any flexibility to knock off another $100 million or so because that surely would alleviate a lot of liquidity tightness discussions surrounding the stock? Secondarily, just in terms of production pro fie, first and second quarter looked pretty flat. Should we expect quite a bit of decline for third and fourth?

Glenn Darden

Well, as we said, in the opening remarks, Irene, this is Glenn, we don't expect to fall off. We're going to maintain our production volumes roughly flat with average volumes for the fourth quarter of 2008, and that is on a much reduced capital program. So we're managing that.

Do we have to do that? No. Could we cut further? Yes, we could. I think I indicated in that my remarks as well. We've already identified another $50 million that doesn't affect production. So in a hunker down mode, we can get down with the best of them and really cut capital program. What we're trying to do is maintain an ongoing efficient operation. It is showing up in our cost structure, and our team is doing a great job of it.

We don't think these prices are going to be down, the commodity prices are going to be down, forever. So we want to be able to keep some continuity on the operating side, but could we cut further? Yes, we could.

Irene Haas - Canaccord

I understand that you have certain balance to strike between the operations as well. One more question. Each quarter now we've seen some pretty big impairment charge, while they are non-cash, it still does influence your debt-to-cap ratio. I'm just kind of wondering, going into the summer, at the end of second quarter, should we be expecting more impairment charges?

Glenn Darden

I think it would depend on what gas price is. Gas price and on a relative basis, reserve life. So, I think the price that we used at the end of the quarter was about $3.50. To the extent that gas prices are lower than $3.50. Of course, there's a number of things to change, cost structure changes, drilling cost change, future development costs change every time you rerun it, but the gas prices are lower, I think you are going to see across industry further impairment charges.

Irene Haas - Canaccord

But do you think the worst is over between fourth quarter and first quarter, in your view?

Glenn Darden

I certainly hope so.

Phil Cook

Plus keep in mind, Irene none of our debt or covenants has any connection to debt-to-cap ratios.

Irene Haas - Canaccord

No, I understood they usually make an adjustment on that, I think. Thanks.

Glenn Darden

This business, of course, is run on cash flow, and the way we manage the business with hedges is not reflected in the ceiling test write-downs, of course.

Irene Haas - Canaccord

Right. And would you consider unwinding some more hedges?

Glenn Darden

It's part of the menu we have. We're not today considering that.

Operator

(Operator Instructions). Your next question is from Gregg Brody with JPMorgan.

Gregg Brody - JPMorgan

Just looking at your cash flow statement it looks like your CapEx was tracking about $15 million ahead of what you incurred for the quarter. Should we expect that to even out during the year or should your actual cash outlays be greater than $500 million?

Glenn Darden

Our actual cash outlays will not be greater than $500 million. You are correct; our capital for the quarter was $190 million, and the cash spent was $255 million. What I said in my remarks is that we'll spend cash of another $250 million between now and the end of the year.

Good morning, everyone. Just a couple follow-up questions. Trying to reconcile your comments on cost per lateral foot and overall well costs coming down 25%. When we think about some of your -- say, Arlington wells, or even wells that cost about $4 million in 2008, and if we think about the ratio of drilling and completion, can you give us an idea of what an average well looks like now and whether most of the cost improvements have been on the drilling or the completion side?

So if we were to reconcile that with, let's say, picking up a new rig today and drilling a new well, what would that new well look like today, if you see what I'm getting at, I'm not asking it very well though.

Glenn Darden

It just depends on the acreage position and the lease situation, but as Toby said, our trend is drilling longer laterals and more frac stages where we can. So we're drilling it at a lower cost today than we did last year, for sure, and those costs have dropped 25% probably across the board. Savings has really been across the board, but most of the savings have been on the completion side.

Michael Jacobs - Tudor, Pickering, Holt

Okay. And also just a follow-up on the new play that you talked about, I know Toby has a pretty good reputation when it comes to gaining a foothold in the more nascent areas before they gain traction with the rest of the industry. When you think about kind of the more prolific shale plays, do you feel like they've all been discovered or are there other stealth areas that we haven't heard about yet?

Toby Darden

Well, you know the stealth plays, as they're called, are not stealth any more. Most of the basins are identified. The key to these plays is efficiency in them, and we, as Glenn mentioned in his remarks, focus on a comprehensive approach to developing the plays which really starts at where does the gas go, how do you minimize the cost to get that gas to market, and then what does it cost you to develop each acre, that is you're holding. Each of the initiatives we're looking at now are in much more granular detail in attacking the shale plays than we have previously looked at them; from infrastructure all the way back to the gas composition of the rock.

So we're getting into pretty serious detail. The toe holds we look at are significant because acreage drives the ultimate recovery, and potential of play.

Glenn Darden

Royalty is important.

Toby Darden

Royalty is another big issue. We've seen in the Barnett alone an extra 5% royalty changes your rate of return in a higher priced gas environment by 40%. So we're very conscious of the royalty. We're being intentionally vague here.

Glenn Darden

I just think that there will be some other plays that are found, and industry has gotten better, but it's all going to boil down to economics. That's where Toby was headed, and that's where our team is really focused on, just how inexpensively can you produce it and what margins can you make in marketing this. So that's truly where our focus is, and I think that you're seeing big differences in existing basins in that regard; Fort Worth basin is case number one for us.

Michael Jacobs - Tudor, Pickering, Holt

The one last follow-up to that, when you think about it from a 30,000 foot strategic view, would you want to diversify geographically to other areas? Could you see yourself going, let's say, east or west, where do you see that from (inaudible)

Glenn Darden

Well, we're way north in BC, so we're in the afraid to go where the gas is.

Operator

The next question comes from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Good morning. On those five rigs that you are operating, if I missed it, I apologize, but where are those going to be operating, the Fort Worth ones, specific to your core and [strategic] non-core acreage at this point?

Glenn Darden

Roughly three to four will be in the northern area, which we consider Lake Arlington and Alliance with one to two in the southern area for the year.

Scott Hanold - RBC Capital Markets

Okay. And I think you addressed somewhat the question on whether or not you lose would some lease-hold. It sounds like you would lose some. Can you give us an idea, when you look at some of your acreage; what percentages have lease expiration issues over the next couple years?

Glenn Darden

Scott what I did say is, we will lose some that we would normally want to lose. So we're holding our core position, so that's roughly 175,000 net acres that we've defined and we've publicized. So we have very few drilling commitments. We probably have, from here 60 wells, maybe 50 wells or so to hold leases. So that's a good thing about our early entry into the basin. We have very few drilling commitments.

Scott Hanold - RBC Capital Markets

Okay, and that 50 to 60 is not something like a this year thing, it's more of that's what you need to commit to the 175 in total over the next few years?

Glenn Darden

Yeah, I think on an annual basis, yes.

Scott Hanold - RBC Capital Markets

Got it. And CapEx, the $500 million, is that all drilling, or there is some stuff related to KGS in there as well?

Glenn Darden

There's definitely midstream capital for Quicksilver in that number.

Scott Hanold - RBC Capital Markets

Okay, so the 500 is Quicksilver's total capital outlay, and what percentage of that would be infrastructure related?

Glenn Darden

There's probably $60 million of that $50 million that's pipe to plant ff the 500.

Scott Hanold - RBC Capital Markets

Whether you are all willing to say about your relationship with BreitBurn at this point in time? What would be your near term goal on getting some resolution to some of the issues that are out there right now?

Glenn Darden

Well, first of all I will say, BreitBurn is a small piece of our overall business. As you know, we are in litigation, and we'll continue that litigation until we believe we get the benefit of the bargain, but we really can't comment on that litigation. So our ideal outcome is to maximize the value and get the benefit of the bargain that we originally struck.

Scott Hanold - RBC Capital Markets

Okay. Can you comment on relative to the current structure of BreitBurn 's board? Would you like to see some change in that at this point?

Glenn Darden

I'd rather not comment at this point, due to the litigation.

Operator

Next question will come from Omar Jama with Owl Creek.

Omar Jama - Owl Creek

One quick question on the NGL price realizations. Those seemed relatively low, and I've noticed that NGL prices generally have trended higher with oil. Do you happen to have handy how the NGL realizations are looking so far in the second quarter?

Toby Darden

You're absolutely correct, Omar that the NGL pricing was extremely low right at the beginning of the first quarter. Those pricings have recovered substantially. Right now I would expect somewhere in the $3 to $4 range increase over the $21 average that we had in the first quarter.

Omar Jama - Owl Creek

Right now about $3, $4 higher, got it. Then another question, I guess more of a broad question; it was pleasant to hear you guys talking about the future of the company. It seems like we're in hunker down mode here, and I guess sooner or later we're going to come out of the recession, and gas prices will be higher. Can you look ahead a little bit and talk about what you're doing to make sure you retain the up side that exists in the business and how impactful some of these new initiatives that you continue to work on could be? Just because you get the sense that when the bonds are trading at $0.60, now they're trading at $0.90 and some of the loans you have out there that people are starting to get a little more optimistic that you are not going to go bankrupt. Can you just talk about what you're doing, what's changed at the company and how you plan for the future?

Phil Cook

Bankruptcy was never a questioned from our side, from our banker's side. So perception out there obviously, the financial world took a big tumble across a lot of sectors. But we are not in full hunker-down mode. We have trimmed significantly our capital budget and our drilling program, but we are maintaining an ongoing program to validate all of our leases that we want to retain, and we're also working on a couple of new projects, Horn River specifically that we believe will be the next leg of our growth.

So we're looking forward, and we're realistic about living within cash flow and paying down debt, but at the same time, we realized that this business will get better, and Quicksilver has got some great assets to capitalize on. We want to maintain the bulk of those assets through this down time, and we're going to hit the ground running as things turn.

So I believe we've got the plan in place to do that. As I said earlier, we've got several things that are working that will improve our balance sheet to enable us to hit it harder when things turn, but overall we're pretty optimistic about where this company is going.

Omar Jama - Owl Creek

And putting a finer point once all of the JVs or as of sales or refinancing transactions are out of the way this year, what would be your ability to ramp CapEx back up in 2010? Do you think it would still be somewhat restrained, and you'd have to live within cash flow again in 2010, or is there some possibility you could start to be a little more aggressive should the gas markets call for that?

Glenn Darden

Well, our view is things have certainly changed, and whether it's permanent on the financial side, it's certainly going to be with us a while. So I don't anticipate Quicksilver outspending its cash flow, but I truly don't view our industry as outspending cash flow, like the industry did or a chunk of the industry, the high-growth players did in the past.

So I just think the financial world has changed, and won't permit that at acceptable borrowing levels or in that regard. So I think that that puts a certain [governor] on growth for the industry, but we have shown in the past that we can grow at very high levels. We're showing this year we can grow at high levels in cutting our budget significantly.

So we're optimistic, as I say, about the future, but I do anticipate that we'll be spending within our cash flow, whatever that cash flow is.

Phil Cook

Omar, one other comment on that, as we've mentioned, we will have quite an inventory of wells to be fracked and put on line, which is a much shorter process than starting from scratch. So the ability to ramp up production is even more robust than ramping up cap spending.

Operator

Next question comes from Subash Chandra with Jefferies.

Subash Chandra - Jefferies

I hopped on late, but two questions. One, did anything come of that deep test in the San Wash basin? And second, the difference in the 255 and the 190, is that the amount that was spent on the '08 accruals?

Phil Cook

This is Phil Cook. With respect to the 190 versus the 255, yes; that was the flow-over from accruals at 12/31. And we're drilling several wells in several areas that we're analyzing, and we are still working on a couple of those areas.

Operator

Your next question will come from Michael Bodino with SMH Capital.

Michael Bodino - SMH Capital

Just a quick question. It looks like with the rig count being split between the northern and southern area, is it fair to assume that about 70% of the wells are going to be in the northern area in the Barnett?

Glenn Darden

Yes.

Michael Bodino - SMH Capital

And given that where you're pushing almost a year into the Alliance deal, can you give us a little bit of sense of what you're seeing in terms of average IPs, average EURs, kind of where that area is moving towards?

Glenn Darden

Our operating team is very enthusiastic about the project. We see very similar characteristics to our Lake Arlington project, which is the best one in our inventory in the Barnett, so we're very high on the project, and we're bringing on additional wells as we speak, and we'll be building out more infrastructure for that as the year progresses. So we're quite happy with that project.

Michael Bodino - SMH Capital

Is there any rule of thumb that for every well you have in the north, it equals two times the production of the well from the south? Is there any way to gauge that, how we think about the reduced CapEx program and what is waiting on completion?

Glenn Darden

Well, there are several variables. The biggest one is the natural gas liquids component of the southern area. So when I say that 70% of our wells will be in the north, we have the capability of shifting as liquids prices improve we may be drilling a few more wells in the southern area, but our rates of return are highest in the Lake Arlington and Alliance area, but our rates of return are very, very good in the southern area. So I don't know that we have just a pure rule of thumb.

Michael Bodino - SMH Capital

Okay. I was trying to figure out how to model the north versus south and just trying to see if there was maybe some easy way to do it. Last question for me, as you kind of move through this year, there's been a lot of talk about transactions, potential transactions in the Barnett Shale, particularly given that big company in Oklahoma City, who we talked about yesterday.

Question for you, obviously anybody who would be looking at potential projects in the Barnett Shale would probably call around to everybody else. Do you get the sense that there's much like there's other guys, a lot of companies sniffing around, looking at ways to enter into more of these shale plays?

Glenn Darden

I'm not sure. We've been contacted by multiple parties in all of our areas, but I'm not sure where the best measure -- I have read what some other players have talked about, but there's interest in the Barnett on our assets. There's interest in the Horn River on our assets and our conventional Canadian assets. So I just think there's a lot of activity around, you just haven't seen a lot of deals made, but I think over time you will over this year.

Operator

Your next question comes from [John Magazino] with Wachovia.

John Magazino - Wachovia

Most of mine have been answered, but I've got a couple quick follow-ups. Going back to your 2010 budget, if you're kind of tied to cash flow next year, do you have a similar maintenance CapEx number that you'd like to use as far as what it takes to you’re your production flat for next year?

Glenn Darden

I think that's probably in the range of $250 million roughly. As Toby talked about, our dollars next year could be spent more on completion than drilling and still keep that production flat. In fact of, we could probably do that with a limited drilling budget for the next three plus years and keep production flat, so we can definitely spend inside of our cash flow in 2010 and do that, but we'll see. We haven't set the budget for 2010 at this point, but we're certainly going to live within our cash flow.

John Magazino - Wachovia

That's very helpful. Going back up to the Horn River, I don't know if I missed this or not, but do you have a cost as far as just the drilling portion of those two wells there--?

Glenn Darden

We haven't broken that out, and obviously these are wells that we've done a lot of science on, full course, and learned some things on the drilling side, so I think going forward, these were $10 million plus type tests at this point, but at overall on the development side, that's going to come down significantly just on pure development.

John Magazino - Wachovia

One final one, this is probably more of a Phil's question. If you look at the asset coverage ratio, can you just walk us through the calculation of that, just remind me and then, kind of, where do you stand right now?

Phil Cook

Well, we don't do the test, obviously, every day, but we perform the PV-10 test at year end. It is based on a three-year strip [held] constant at the end of the three-year strip with whatever that price is in the third year. It also includes our current cost structure, which includes the benefit of ownership of KGS as well as our hedges. So we passed the test at year end. We passed the test at the end of the quarter.

Operator

Your next question comes from [Steven Koppel] with Credit Suisse.

Steven Koppel - Credit Suisse

First, for the asset test, can you give the numbers as of 3/31?

Phil Cook

Steven, we run the PV-10 at year end, and we use that same PV-10 for performance of the test at the quarter. Now, we'll run the PV-10 again at 6/30. So the PV-10 number did not change. We've disclosed that number in our 10-K. It's about $4 billion.

Steven Koppel - Credit Suisse

Right. But per your calculation how close were you at 3/31 on the total coverage and the secured debt coverage?

Phil Cook

I think the total debt coverage was roughly $100 million, and maybe the secured debt number, if you took into account the cash that we have on the balance sheet, I think was maybe $60 million.

Steven Koppel - Credit Suisse

The decision to monetize hedges, how much of an impact did that have on the calculation?

Phil Cook

I certainly considered the test, but we were really looking at was how much money did we borrow in the first quarter and we were trying to minimize that.

Steven Koppel - Credit Suisse

Then secondly, as I was looking at the KGS balance sheet, the obligation now back to Quicksilver, I think is something around $180 million. With the increase in KGS' stock price, is there any thought to potential transaction there?

Phil Cook

We're always looking at KGS as well as Quicksilver with respect to the capital structure, and as Glenn said, we're working on a number of different things. Some of those include refinancing. Some of those include other sorts of transactions. So we're thinking about a lot of different things with respect to both companies.

Operator

Next question comes from Stephen Beck with Jefferies & Company.

Stephen Beck - Jefferies & Company

Good morning. Just one quick question. If I recall, you were expecting a federal tax refund of about $50 million. Is that still expected in the third quarter or so?

Phil Cook

Yeah, actually, we got it on April 1st. It was $41 million. There's another about $7 million or 8 million of AMT that we paid that we'll get back in a future year.

Operator

Next question will come from Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Just a couple quick things. If we look at that the Barnett, and assume that the prices we're at now are not going to last forever, looking ahead a bit, I'm thinking about the number of rigs that were running in the play overall and how those peaked and how a number of those have moved to other regions and so forth. Do you have any sense of in a rebound scenario, how, -- just what percentage or how many rigs you think realistically could get added back into the play say over a six-month period?

In other words, how easy would it be for the industry to ramp up? Are there a lot of rigs that maybe weren't optimal that might be less likely to come back? Do you have any thoughts on that?

Glenn Darden

Well, I think one big factor is priority of capital spend and drilling budget for the big players in the basin. And some of the players have been very active in other basins after they had been active in the Fort Worth basin, so I think some of that budget does get diverted, so you don't have the rig count possibly hit the numbers that it did before. A lot of drilling has been done in some of the better areas. A lot of drilling has been done in Johnson County. A lot of that inventory has been drilled, but there's still plenty of locations to drill. Our view is the rig count doesn't hit where it peaked.

Noel Parks - Ladenburg Thalmann

Just one other thing. Where did you leave off with the Horseshoe Canyon (inaudible)? I know that was a topic in the past, just wanted to know where that stood. I know you are going to be reducing the activity, but was wondering what that looked like?

Glenn Darden

Well, our testing program worked quite well. So we've increased our inventory of wells. We're just not going to drill those infill locations at these commodity prices. So as things improve, we've got those to look forward to drilling.

Noel Parks - Ladenburg Thalmann

And just given the difference to NYMEX what sort of pricing would you really want to see before you felt enthusiastic about going forward up there as opposed to putting incremental dollars into the Barnett?

Glenn Darden

Well, as you know, Quicksilver Resources Canada, has lived on its own cash flow. So that's a function of how that lives, is it north of $5, probably?

Operator

Your last question is a follow-up question from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Thanks, it's been answered.

Operator

At this time there are no further questions. Mr. Buterbaugh, would you like to make any closing remarks?

Rick Buterbaugh

Yes, thank you, Jennifer. Just as a reminder, a replay of this call will be available on the company's website for 30 days. Quicksilver will release our second quarter 2009 earnings on Monday, August 10, 2009, prior to market open. Members of the company's management team will be presenting at various investor conferences over the coming quarter and details on these presentations will be available on our website.

Thank you for your time and interest in Quicksilver this morning. This concludes our call.

Operator

Thank you for participating in today's Quicksilver first quarter 2009 earnings conference call. You may now disconnect.

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